Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A. This well, which was drilled with cable tools, started the modern petroleum industry.
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
In recent years, deformation of the reservoir host rocks has become a subject of great interest, prompted in part by the dramatic subsidence observed at Ekofisk platforms in the North Sea. One method of monitoring deformation is by passive seismic monitoring. It is called "passive" because the geopysicist does not activate a seismic source, but rather uses existing geophones to monitor ongoing changes in the rocks due to downhole conditions. Deformation is an important aspect of reservoir production, even without a significant compaction drive in many cases. Previous studies have been published in the scientific and earthquake literature relating earthquakes to oil/gas production and to injection practices.
These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. For example, consider the isothermal, three-phase, compositional case with all components present in all three phases. There are m 2n 1 constraint equations consisting of the volume balance and the 2n equations expressing equal fugacities of ...
If pore volume contraction contributes prominently to overall expansion while the reservoir is saturated, then the reservoir is classified as a compaction drive. Compaction drive oil reservoirs are supplemented by solution gas drive if the reservoir falls below the bubblepoint; they may or may not be supplemented by a water or gas cap drive. Compaction drives characteristically exhibit elevated rock compressibilities, often 10 to 50 times greater than normal. Rock compressibility is called pore volume (PV), or pore, compressibility and is expressed in units of PV change per unit PV per unit pressure change. Rock compressibility is a function of pressure.
Reservoir simulation is a widely used tool for making decisions on the development of new fields, the location of infill wells, and the implementation of enhanced recovery projects. It is the focal point of an integrated effort of geosciences, petrophysics, reservoir, production and facilities engineering, computer science, and economics. Geoscientists using seismic, well-log, outcrop analog data and mathematical models are able to develop geological models containing millions of cells. Simulation of the reservoir at the fine geologic scale, however, is usually not undertaken except in limited cases. Generally, the fine-scaled geological model is partially integrated or "upscaled" to a coarse-grid model, which is computationally more tractable.
All drilling challenges relate to the fundamental objective of maintaining a workable wellbore throughout the well-construction process. A workable wellbore can be drilled, logged, cased, cemented, and completed with minimal nonproductive time. The design of the drilling-fluid system is central to achieving this objective. With a poorly designed system there are some challenges that will occur. Most operational problems are interrelated, making them more difficult to resolve.
In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...